The exemplary embodiments described herein relate to methods for selectively replacing the larger particles screened from a drilling fluid.
Drilling fluids often include a plurality of particles that impart specific properties (e.g., viscosity, mud weight, and the like) and capabilities (e.g., wellbore strengthening) to the drilling fluid. It should be understood that the terms “particle” and “particulate,” as used in this disclosure, includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and combinations thereof.
For example, weighting agents (i.e., particles having a specific gravity greater than the base fluid of the drilling fluid) can be used to produce drilling fluids with the desired mud weight (i.e., density), which affects the equivalent circulating density (“ECD”) of the drilling fluid. During drilling operations, for example, the ECD is often carefully monitored and controlled relative to the fracture gradient of the subterranean formation. Typically, the ECD during drilling is close to the fracture gradient without exceeding it. When the ECD exceeds the fracture gradient, a fracture may form in the subterranean formation and drilling fluid may be lost into the subterranean formation (often referred to as lost circulation). In another example, lost circulation materials (“LCMs”) can be used to strengthen the wellbore and increase the hoop stress around the wellbore, which allows for a higher ECD. The LCMs incorporate into and plug microfractures extending from the wellbore, so as to mitigate fracture propagation and lost circulation.
The properties and capabilities that the particles impart on the drilling fluid depend on, inter alia, the particle size distribution (“PSD”) of the particles, the specific gravity of the particles, the concentration in the drilling fluid, and the like. In many instances, to achieve the desired properties in the drilling fluid, a mixture of types of particles (e.g., varying by composition, shape, or the like) are used. Typically, the PSD of the particles in a drilling fluid is broad.
During many drilling operations, the drilling fluid is circulated through the wellbore (e.g., down the drill string and back up through the annulus between the drill string and the wellbore), passed through shakers to remove cuttings and debris produced during drilling, and recirculated back into the wellbore. Shakers typically include one or more screens with holes of a specific size (also referred to as the mesh size of the screen) to allow smaller particles and fluid through but retain larger particles for removal.
In removing the cuttings with shaker systems, some of the particles in the drilling fluid that impart the desired properties and capabilities are also removed, thereby adversely altering the properties and capabilities of the drilling fluid. To account for these changes, operators are required to add more particle additives (e.g., weighting agents and LCMs) back into the drilling fluid. However, the shaker removes only the particles larger than the screen size, and the particle additives mixed into the drilling fluid have a broad PSD. Therefore, to fully replace the concentration of larger particles, the concentration of smaller particles increases, and the PSD remains changed. Further, the total volume percent of the particles in the drilling fluid increases. The higher volume percent increases the viscosity and, as a consequence of the particles' specific gravity, increases the density of the drilling fluid.
To combat the changes to fluid properties, operators often dilute the drilling fluid and add additional additives to maintain the desired fluid properties, such as emulsifiers and the like. Often the base fluid used to dilute the drilling fluid and the other additives are expensive. Additionally, a dilution approach increases the overall volume of fluid that the operator has to handle or have stored on-site or shipped to the well site, which further increases costs and complicates logistics, especially in off-shore drilling. However, while the viscosity may be addressed to some degree by dilution, the PSD is still not the same as the original PSD (i.e., the smaller diameter particles have a higher concentration relative to the larger particles), which imparts different properties to the drilling fluid. Since drilling fluid is circulated several times through the wellbore during drilling operations, this problem of maintaining drilling fluid properties and the consequences of common dilution techniques can become cumulative and expensive.